Downhole data, fiber optics helping to drive production gains

Elaine Maslin reports on how the oil and gas industry is getting more data from downhole thanks to fiber optics (First published in the December 2017 OE, access the full issue here).

The big data revolution is being felt in the oil and gas industry with a large focus on the gains to be made from the mass of data the industry already generates.

Image: Nexen's Golden Eagle platform.

But, there are yet more gains to be made if more information could be extracted from downhole, not least in an environment where operators want to get more out of their existing assets. Such ideas were discussed at the SPE Aberdeen Inwell Flow Surveillance & Control Seminar early October. "Wells are not disposable assets. We have to make the most out of the well stock we have got,” says Mike Webster, chairman of the event. “For me, the only way of doing that is through robust and frequent surveillance."

The problem is justifying the expense, he says. However, the payback can be many times over. "We don't get the value unless we then use the data in some shape or form," says Webster, who previously worked in senior roles for BP and is now director of Production Petrophysics, a consultancy.

So, how do you get more data from downhole? A large focus in the well surveillance space in recent years has been on fiber optics. For the converts, this is a technology worth putting downhole, even if you don’t quite know what you’ll get from it. “With fiber optics you can get data down the length of the well, for every meter it's deployed,” Webster says. “When you stick fiber in the ground you don’t know everything you are going to find out, and there will be multiple ways of using all that data.”

According to downhole technology development firm Well-Sense’s founder Dan Purkis, fiber optics are set to take off. He told the SPE event that there are about 200-300 installations a year at the moment, but this will become thousands in not that many years’ time.

A renaissance

It’s taken a while for the industry to come to grips with fiber. It was introduced in the late 1990s, but there were problems getting the fiber into the well and the longevity of it, Webster says. The fiber darkened due to exposure to water and hydrogen and other by-products of corrosion in the well environment. There were also connectivity issues, and mechanical issues with fiber could damage it.

It was initially used for distributed temperature sensing (DTS), but the introduction of using fiber for distributed acoustic sensing (DAS) has led to a “renaissance” in the technology and it’s potential, however. “A big change was the advent of DAS,” Webster says. “Only so much can be done with temperature and it was over-egged. With the addition of acoustic, the utility of both is far more robust and created renaissance in fiber. Plus, there is now increased reliability and an increased choice in deployment [methods], which opens it up to use in a larger choice of wells.” At the same time, the capabilities of DTS are also growing.

Fiber can be installed permanently or used in temporary interventions. Permanent installation could be with a downhole pressure/temperature (PT) gauge cable down to just above the production packer, which doesn’t cover as much of the well as you might want. Going below the production packer in a multi-trip completion means using a wet connect downhole, which have proven problematic. Otherwise, it could be installed via a hydraulic conduit, which means cost. Various well intervention methods can be used, including coiled tubing, carbon fiber rod, which has the benefit of being able to be pushed down horizontal wells, or in conventional wells using slickline and e-line, Webster says.

Slickline

Paradigm Intervention Technologies has developed a standard 0.125in slickline deployment system, able to be packed into a 5700kg container (total loaded weight), which can use existing slickline infrastructure on facilities. The fiber wire, housed on a drum, is terminated with optical connections.

It’s CO2 and H2S resistant, can withstand up to 150°C (and could be higher), and comes in up to 6km lengths (currently manufacturing standard), but has a lower tensile strength than standard slickline because it’s hollow (1400lb), Webster, who presented for Paradigm, said. It contains single mode fiber for acoustic monitoring and multi-mode fiber for temperature sensing. Paradigm has its own depth control sheaves and stuffing box, but it can be used with existing onboard systems, Webster says. The system also has DTS and DAS optical interrogation units feeding data into a laptop.

The DAS in Paradigm’s system typically uses a 100-nanosecond pulse width, which gives 10m spatial resolution, for application such as looking for leaks and defects in the well, Webster says. The DTS has 0.06°C thermal resolution, 1.02m spatial resolution, using a 5min stack time increment.

These are sufficient for well integrity type applications, Webster says. A system for the likes of seismic application would require higher sensitivity. Giving an example, Webster says the system was deployed to investigate an A annulus leak and took 13 hours from rig up to rig down, with five hours survey time, collecting 1.9TB of raw DAS data and 14.3MB raw DTS data, which was decimated to 1GB, and integrated with other well data within three days. With optimization of the workflow this can now be done in 24 hours, Webster says.

Temperature readings

Garth Naldreth, vice president, Oil & Gas, at fiber sensing firm Silixa, told the SPE event that DTS resolution has improved, to below 50cm, and with increased temporal resolution. It can be installed behind the casing or with a wireline or slickline type system for flow profile, leak detection, gas lift monitoring, etc. "For one product in the well there are a lot of opportunities," he says, including getting production profiling and phase information.

In work Silixa has done, slugging within a well was monitored and the data then interpreted and visualized, so that it could be shown when and where the slugs form and how they travelled along the well towards an electric submersible pump (ESP). This helped an operator to see where gas was coming into the well to cause the slugging – information was used to take action and prevent damage to the ESP. Normally, you can’t production log across an ESP, Naldreth says. As fiber systems continue to improve more can be done with these measurements and now Doppler shifts in acoustic data are being used to generate enhanced flow profiling he says.

Heriot-Watt University Professor Khafiz Murador told the SPE event that temperature measures used for monitoring near-well conditions are better than traditional pressure, as the temperature signals propagating less. But, while pressure transient analysis has been well-developed, temperature transient analysis, not so much.

“It’s not been used much before because of the many different influences on temperature making it complex to model, but with the help of the data available from Nexen’s Golden Eagle field, this work has been made easier,” Murador says. The field’s platform and subsea wells have been fitted with permanent DTS, as well as downhole pressure and temperature gauges (OE: Gaining Control, April 2017).

To date, 19 wells have been completed on the field, which came onstream in October 2014. Data from the DTS system and downhole PT gauges has given Murador the data needed for work on temperature transient analysis. “This type of analysis could provide insight which could compensate for failed ICVs or sensors and reduce well or zonal flow tests,” he says.

Soundings

Acoustic data is also giving operators a lot of information about their wells. DAS was used for sand ingress monitoring and remediation on BP’s Azeri, Chirag and Gunalshi fields in the Caspian Sea, Webster says. These are reservoirs with long production intervals, but soft unconsolidated rock prone to sand production. The wells were installed with fiber in many cases via a hydraulic conduit.

DAS was used to see where there was sand ingress, using digital processing – having done testing and then correlation with a surface sand meter – to discriminate from other forms of noise in the well, such as sand transportation, Webster says.

“A sand log was created for targeted remediation in as near real-time as possible,” he says, compared to the early days when DAS measurements were delivered in stacks of hard drives. This helped visualize the slugs and aid understanding of the mechanism for sanding in the well, which then enabled remediation work and a 70% sand production reduction, with oil production increasing by 2000 b/d (from one well). With the data now able to be visualized real-time, engineers can respond real-time, Webster says.

A small sacrifice

Well-Sense has been developing technology to take measurements downhole using fiber, but in single shot runs using a sacrificial fiber and deployment system (OE: Downhole disintegration, June 2016). It would be sent down the well, with readings taken, then left in the well to erode (the materials used to make the sub chosen for this purpose). Well-Sense is now working on a version which could be pumped down the well, for long horizontal wells, where using gravity deployment wouldn’t be feasible. It’s hoping to do a 10km vertical well deployment in Germany also, Purkis says (pictured left).